System and method for hydrocarbon recovery and extraction

ABSTRACT

Some embodiments teach a method of recovering hydrocarbons from a hydrocarbon formation. The method including: (a) generating injection gas, the injection gas having at least a predetermined pressure and a predetermined temperature; (b) injecting the injection gas into the hydrocarbon formation, and (c) recovering the hydrocarbons from the hydrocarbon formation. Other embodiments are disclosed in this application.

FIELD OF THE INVENTION

This invention relates to systems and methods for recovering, extracting, and refining hydrocarbons from the Earth and more particularly, systems and methods for recovering and refining oil from hydrocarbon formations using synthesis gas and/or other gases.

BACKGROUND

As world reserves of light, sweet crude oil diminish and worldwide consumption of oil increases, oil production companies seek methods and systems for extracting useful oils from heavier crude oil reservoir. The heavier crude oil, which can include bitumen, heavy oil, shale oil, and tar sand poses processing and production problems primarily due to its viscosity. Using traditional methods, recovery of the useful oils or hydrocarbons is expensive due to equipment cost, substantial energy, and materials used during the recovery process. Furthermore, the high cost combined with the technical challenges of producing useful oils from the heavier crude oil have limited the development of such recovery processes.

As die demand of hydrocarbons continues to increase, methods and systems are needed that allows recovery and extraction of useful oils or hydrocarbons from heavier crude oil without the high cost and technical problems of traditional methods.

BRIEF DESCRIPTION OF THE DRAWINGS

To facilitate further description of the embodiments, the following drawings are provided in which:

FIG. 1 illustrates a hydrocarbon recovery system for recovering hydrocarbons from a hydrocarbon formation, according to a first embodiment;

FIG. 2 illustrates a method of recovering hydrocarbons from a hydrocarbon formation, according to the first embodiment;

FIG. 3 illustrates a hydrocarbon recovery system for recovering hydrocarbons from a hydrocarbon formation, according to a second embodiment;

FIG. 4 illustrates a hydrocarbon recovery system for recovering hydrocarbons from a hydrocarbon formation, according to a third embodiment;

FIG. 5 illustrates a hydrocarbon recovery system for recovering hydrocarbons from a hydrocarbon formation, according to a fourth embodiment;

FIG. 6 illustrates a hydrocarbon recovery system for recovering hydrocarbons from a hydrocarbon formation, according to a fifth embodiment;

FIG. 7 illustrates a method of recovering hydrocarbons from a hydrocarbon formation, according to the fifth embodiment; and

FIG. 8 illustrates a method of method of recovering hydrocarbons from two or more hydrocarbon formations using one or more gasifiers, according to a sixth embodiment.

For simplicity and clarity of illustration, the drawing figures illustrate the general manner of construction, and descriptions and details of well-known features and techniques may be omitted to avoid unnecessarily obscuring the invention. Additionally, elements in the drawing figures are not necessarily drawn to scale. For example, the dimensions of some of the elements in the figures may be exaggerated relative to other elements to help improve understanding of embodiments of the present invention. The same reference numerals in different figures denote the same elements.

The terms “first,” “second,” “third,” “fourth,” and the like in the description and in the claims, if any, are used for distinguishing between similar elements and not necessarily for describing a particular sequential or chronological order. It is to be understood that the terms so used are interchangeable under appropriate circumstances such that the embodiments described herein are, for example, capable of operation in sequences other than those illustrated or otherwise described herein. Furthermore, the terms “include,” and “have,” and any variations thereof, are intended to cover a non-exclusive inclusion, such that a process, method, system, article, device, or apparatus that comprises a list of elements is not necessarily limited to those elements, but may include other elements not expressly listed or inherent to such process, method, system, article, device, or apparatus.

The terms “left,” “right,” “front,” “back,” “top,” “bottom,” “over,” “under,” and the like in the description and in the claims, if any, are used for descriptive purposes and not necessarily for describing permanent relative positions. It is to be understood that the terms so used are interchangeable under appropriate circumstances such that the embodiments of the invention described herein are, for example, capable of operation in other orientations than those illustrated or otherwise described herein.

The terms “couple,” “coupled,” “couples,” “coupling,” and the like should be broadly understood and refer to connecting two or more elements or signals, electrically, mechanically through intervening circuitry and/or elements. Two or more electrical elements may be electrically coupled, either direct or indirectly, but not be mechanically coupled; two or more mechanical elements may be mechanically coupled, either direct or indirectly, but not be electrically coupled; two or more electrical elements may be mechanically coupled, directly or indirectly, but not be electrically coupled. Coupling (whether only mechanical, only electrical, etc.) may be for any length of time, e.g., permanent or semi-permanent or only for an instant.

“Electrical coupling” and the like should be broadly understood and include coupling involving any electrical signal, whether a power signal, a data signal, and/or other types or combinations of electrical signals. “Mechanical coupling” and the like should be broadly understood and include mechanical coupling of all types.

The absence of the word “removably,” “removable,” and the like near the word “coupled,” and the like does not mean that the coupling, etc. in question is or is not removable.

DETAILED DESCRIPTION OF EXAMPLES OF EMBODIMENTS

Some embodiments teach a method of recovering and extracting hydrocarbons from a hydrocarbon formation. The method can include: (a) generating injection gas; (b) injecting the injection gas into the hydrocarbon formation with at least a predetermined pressure and a predetermined temperature; and (c) recovering the hydrocarbons from the hydrocarbon formation.

Various embodiments teach a hydrocarbon recovery system configured to recovering hydrocarbons from a hydrocarbon formation. The system can include: (a) a gasifier configured to produce synthesis gas; (b) one or more injection wells located at least partially in the hydrocarbon formation; and (c) one or more productions wells located at least partially in the hydrocarbon formation. The one or more injection wells can be coupled to an output of the gasifier and configured to receive at least a first portion of gas in the synthesis gas from the gasifier and conduct the at least the first portion of the synthesis gas into the hydrocarbon formation. The one or more production wells can be configured to remove at least a first portion of the hydrocarbons out of the hydrocarbon formation.

The same or different embodiments can teach a method of obtaining petroleum from an oil reservoir and at least partially refining at least a first portion of the petroleum in an underground cavern located in a vicinity of the oil reservoir. The method can include: (a) providing a first injection gas; (b) pumping the first injection gas into at least one injection well in the oil reservoir; (c) draining at least a second portion of the petroleum from the oil reservoir into the underground cavern; (d) providing a second injection gas; and (e) pumping the second injection gas into the underground cavern such that the at least the first portion of the petroleum in the underground cavern is at least partially refined by the second injection gas.

Further, embodiments can teach a system configured to obtain petroleum from an oil reservoir. The system can include: (a) a gasifier configured to produce synthesis gas; (b) one or more injection wells in the hydrocarbon formation; (c) one or more transportation wells configured to drain at least a first portion of the petroleum from the oil reservoir into the underground cavern; and (d) one or more production wells coupled to the underground cavern. The one or more injection wells can be coupled to an output of the gasifier and configured to receive at least a first portion of the synthesis gas from the gasifier and conduct the at least the first portion of the synthesis gas into the oil reservoir. The one or more production wells can be configured to conduct at least a first portion of the petroleum out of the underground cavern.

Still further embodiments teach a method of recovering hydrocarbons from two or more hydrocarbon formations using one or more gasifiers. The method can include: (a) providing the one or more gasifiers at a first one of the two or more hydrocarbon formations; (b) generating a first injection gas using the one or more gasifiers; (c) injecting the first injection gas from the one or more gasifiers into the first one of the two or more hydrocarbon formations; (d) recovering the hydrocarbons from the first one of the two or more hydrocarbon formations; (e) moving the one or more gasifiers from the first one of the two or more hydrocarbon formations to a second one of the two or more hydrocarbon formations; (f) generating a second injection gas using the one or more gasifiers at the second one of the two or more hydrocarbon formations; (g) injecting the second injection gas from the one or more gasifiers into the second one of the two or more hydrocarbon formations; and (h) recovering the hydrocarbons from the second one of the two or more hydrocarbon formations.

Yet other embodiments teach a method of recovering hydrocarbons from a hydrocarbon formation using one or more gasifiers. The method can include: (a) providing the one or more gasifiers at a first location at the hydrocarbon formation; (b) generating a first injection gas using the one or more gasifiers at the first location at the hydrocarbon formation; (c) injecting the first injection gas from the one or more gasifiers into the hydrocarbon formation; (d) recovering a first portion of the hydrocarbons from the hydrocarbon formation; (e) moving the one or more gasifiers from the first location at the hydrocarbon formation to a second location at the hydrocarbon formation; (f) generating a second injection gas using the one or more gasifiers at the second location at the hydrocarbon formation; (g) injecting the second injection gas from the one or more gasifiers into the hydrocarbon formation; and (h) recovering a second portion of the hydrocarbons from hydrocarbon formation.

Turning to the drawings, FIG. 1 illustrates a hydrocarbon recovery system 100 for recovering hydrocarbons from a hydrocarbon formation 101, according to a first embodiment. System 100 is merely exemplary and is not limited to the embodiments presented herein. System 100 can be employed in many different embodiments or examples not specifically depicted or described herein. As used herein, in some examples, recovery can refer to both recovery and extraction.

In some examples, oil reservoir or hydrocarbon formation 101 can be oil deposits in an oil sands (e.g., the Athabasca tar sands located in Alberta, Canada), oil shale (e.g., the Green River Formation in the western United States), or other geological formations in which oil or other hydrocarbons are located.

In some embodiments, hydrocarbon recovery system 100 can include: (a) at least one gasifier 110; (b) at least one gas separator 120; (c) a steam turbine 122; (d) at least one sulphur removal system 124 coupled to the output of gasifier 110; (e) at least one pump/compressor 126 coupled to the output of sulphur removal system 124; (f) at least one injection well 150 coupled to compressor 126 and at least partially located in hydrocarbon formation 101; (g) at least one production well 152 at least partially located in hydrocarbon formation 101; (h) at least one pump 130 coupled to production well 152; (i) at least one water separator 132 coupled to the output of pump 130; (j) an above-ground refining facility 134; (k) an above-ground storage facility 136; (l) at least one coker 138; (m) at least one sulphur removal system 139 with an input coupled to coker 138 and an output coupled to gas separator 120; (n) at least one compressor 140 with an input coupled to gas separator 120 and an output coupled to refining facility 134; and (o) at least one heat exchanger 121.

As an example, each part of system 100 (except, in some examples, above-ground refining facility 134 and/or above-ground storage facility 136) can be located within 1000 meters of the point on the surface of the earth directly above any part of hydrocarbon formation 101 or the point on the earth's surface where injection well 150 enters the earth. In other examples, each part of system 100 (except, in some examples, above-ground refining facility 134, and/or above-ground ground storage facility 136) can be located within 1000 meters of the edge of the mineral lease containing hydrocarbon formation 101. In still other examples, each part of system 100 (except, in some examples, above-ground refining facility 134, and/or above-ground storage facility 136) can be located directly over hydrocarbon formation 101 and/or the mineral lease to reduce cost. In yet another embodiment, each part of system 100 (except, in some examples, above-ground refining facility 134 and/or above-ground storage facility 136) can be located within 10,000 meters of the point on the earth's surface where injection well 150 enters the earth

Not to be taken in a limiting sense, a simple example of a method of operation of system 100 could involve a portable gasifier 110 generating a hot synthesis gas or syngas from a variety of input materials. One or more gases in the syngas can be separated out to form an injection gas. A hot injection gas can be pumped into injection well 150 under a predetermined pressure. In some examples, the hot injection gas heats viscous hydrocarbons in hydrocarbon formation 101 to reduce the viscosity of the hydrocarbons and, thus, increasing their ability to flow. Furthermore, the hot injection gas can upgrade or refine the hydrocarbon (e.g., through hydrocracking, thermal cracking, and/or hydrotreating) before the hydrocarbons are pumped from the earth. The hydrocarbons from hydrocarbon formation 101 can flow from the region around injection well 150 through the earth to production well 152 and then can be pumped to an above-ground refining facility 134. The hydrocarbons can be further refined in refining facility 134 and stored in above-ground storage facility 136. Exhaust gases and other byproducts (i.e., feedstock 103 (e.g., petroleum coke or pet coke)) of the refining process can be used as fuel or feedstock for gasifier 110.

Synthesis gas or syngas, as used herein, can refer to a gas mixture that comprises varying amounts of at least hydrogen (H₂), and carbon monoxide (CO). In the same or different embodiments, the syngas can also contain carbonyl sulfide (COS), hydrogen sulfide (H₂S) carbon dioxide (CO₂), methane (CH₄). The syngas can also contain other gases (e.g., C₁ through C₅ gas) in small amounts.

In some examples, the syngas is generated by the gasification of carbon-containing fuel. Typically, syngas has half or less than half the energy density of natural gas. In many embodiments, the amount of H₂ is greater than the amount of CO in the syngas. Furthermore, in the syngas, the amount of CO can be greater than the amount of CO₂, which can be greater than the amount of CH₄. Other gas can be included in the syngas in smaller, varying amounts. In numerous embodiments, the gas composition (e.g., the proportions by weight and/or volume of each gas in the mixture) produced by gasifier 110 is tunable. That is, the composition of the syngas can be based on the specific physical and chemical properties (e.g., hydrocarbon viscosity, formation permeability, depth of the hydrocarbons) desirable for extraction and recovery of hydrocarbons from the specific hydrocarbon formation at that specific point in time.

In some embodiments, gasifier 110 can convert a feedstock of solid carbonaceous materials (e.g., petroleum coke, coal, agricultural waste, forestry waste, or other organic materials) into syngas. In the example illustrated in FIG. 1, gasifier 110 can use petroleum coke as a feedstock. Furthermore, in the same or different embodiments, gasifier 110 can also use exhaust gas and byproducts from the refining of hydrocarbons in refining facility 134 as fuel or feedstock. In these embodiments, system 100 can be entirely or substantially self-contained or self-dependent after starting up because the waste or byproducts of the refining process can be used to produce the syngas needed for system 100. In various embodiments, gasifier 110 can be identical or similar to the gasifier described in PCT Application Publication No. WO 2007/121268, filed 11 Apr. 2007 and entitled Method and Apparatus For Solid Carbonaceous Materials Synthesis Gas Generation, which is incorporated herein by reference. In various examples, gasification can include pyrolysis and thermolysis.

In many embodiments, gasifier 110 is portable. Using a portable gasifier would allow the gasifier to be moved from a first hydrocarbon formation to a second hydrocarbon formation, for example, when all of the removable hydrocarbons have been removed from the first hydrocarbon formation. The portable gasifier can also be moved from location to location of the same hydrocarbon formation. Thus, using a portable gasifier would decrease the cost of development of a hydrocarbon recovery system.

Gasifier 110 can also heat the syngas. In some examples, gasifier 110 can include a heating system (not shown) that heats the syngas such that the syngas has a temperature between 350° C. and 1,850° C. In the same or different example, the syngas is heated as part of the production process.

After leaving gasifier 110, the syngas can be pumped into heat exchanger 121 coupled to the output of gasifier 110. Heat exchanger 121 can be configured to transfer heat from the syngas leaving gasifier 110 to (a) steam or water used by steam turbine 122; and (b) injection gas from compressor 126 before the injection gas is injected into hydrocarbon formation 101. In some examples, sulphur removal system 124 can only remove sulphur from gas at or around ambient temperature (e.g. 18° C. to 24° C.). Accordingly, the temperature of the syngas leaving gasifier 110 must be cooled before being provided to sulphur removal system 124. Using heat exchanger 121 to remove the heat from the syngas and use it to heat steam/water from steam turbine 122 and the injection gas can be an efficient and cost-saving measure. In some examples, the cooled syngas, leaving heat exchanger 121, is provided to sulphur removal system 124.

In some examples, the injection gas is heated in heat exchanger 121 to a temperature greater than 1000° C. or greater than 1200° C. In other examples, the injection gas is heated to a temperature greater than 700° C. In the same or different examples, heat exchanger 121 is configured to allow the syngas temperature before injection to correspond to the specific physical and chemical properties desirable for extraction and recovery of hydrocarbons from the specific hydrocarbon formation.

Steam turbine 122 can be used to generate electrical power for system 100. In some examples, some of the hot syngas from gasifier 110 (or heat from the hot syngas) can be used to create steam, which turns steam turbine 122. For example, steam turbine 122 can use produce steam using heat from heat exchanger 121.

In various examples, steam turbine 122 can produce electrical power. In some examples, the electricity produced by steam turbine 122 can be used to at least partially operate system 100. In some of these embodiments, system 100 can be entirely or substantially self-contained or self-dependent after startup because the waste or byproducts of the refining process can also be used to produce the electricity (and other materials) that system 100 needs. In other examples, system 100 does not include steam turbine 122.

Sulphur removal system 124 can at least partially remove the sulphur containing compounds from the syngas. An output of sulphur removal system 124 can be coupled to compressor 126. In some embodiments, an output of sulphur removal system 124 can be also be coupled to an input of gas separator 120 and provide syngas to gas separator 120. In some examples, the syngas can be the injection gas after sulphur containing compounds have been removed from the syngas.

Pump/compressor 126 can be used to compress the injection gas and pump the injection gas into injection well 150. Compressor 126 can output high pressure injection gas to injection well 150. For example, compressor 126 can output injection gas with a pressure up to 1500 psig (pounds-force per square inch gauge). In the same or different embodiments, compressor can output injection gas with a pressure in the range of 150 to 500 psig. In the same or different examples, compressor 126 is configured to allow the injection gas pressure before injection to correspond to the specific physical and chemical properties desirable for extraction and recovery of hydrocarbons from the specific hydrocarbon formation. In other embodiments, the injection gas is not pressurized by compressor 126, but is pumped into injection well 150.

Heat exchanger 121 can heat the injection gas after the gas is compressed. In some examples, the combination of heat exchanger 121 and compressor 126 can heat and pressurize the injection gas such that at least a portion of the injection gas is in a supercritical state. That is, the injection gas has a predetermined pressure and predetermined temperature in such ranges that at least one or more of the gases in the injection gas are in a supercritical state. For example, if the injection gas includes carbon dioxide, the carbon dioxide will be in a supercritical state if the pressure is above 7400 kilopascals and the temperature is above 30° C. If the injection gas includes hydrogen, the hydrogen will be in a supercritical state if the pressure is above 1300 kilopascals and the temperature is above −240° C. Supercritical gas has increased ability to diffuse through solids (e.g., viscous hydrocarbons or the Earth) and also has increased solvency properties.

At least one injection well 150 can be drilled into hydrocarbon formation 101. Injection well 150 can be comprised of or be lined with an inert material that does not react with the injection gas. In some examples, injection well 150 can at least partially comprise or be lined with stainless steel.

In some embodiments, injection well 150 can include a substantially vertical portion 153 and a substantially horizontal portion 154. The substantially horizontal portion can be located in a part of hydrocarbon formation 101 that contains hydrocarbons. In the same or different examples, portion 154 is not substantially horizontal, and portion 153 is not substantially vertical. The length of substantially vertical portion 153 depends on the depth of the hydrocarbons below the surface of the Earth and the permeability and porosity of the hydrocarbon formation. In various examples, the length of substantially horizontal portion 154 can be approximately 500 meters. In the same or different embodiments, horizontal portion 154 can be slotted. In other examples, all of injection well 150 is slotted.

In some examples, the distance between adjacent injection wells can be greater than approximately five meters. In other examples, the distance between adjacent wells can be approximately fifteen meters or even greater than fifty meters. In the same or different examples, the distance between adjacent injection wells corresponds to the specific physical and chemical properties desirable for extraction and recovery of hydrocarbons from the specific hydrocarbon formation. Each injection well can have its own compressor, or some or all of the injection wells can share the same compressor. The same variations can also apply to the gasifier, the steam turbine, the sulphur removal system, and the heat exchanger.

In addition to drilling at least one injection well 150 into hydrocarbon formation 101, at least one production well 152 can be drilled into hydrocarbon formation 101. In some embodiments, injection well 150 can include a substantially vertical portion 155 and a substantially horizontal portion 156. In the same or different examples, portion 156 is not substantially horizontal and portion 155 is not substantially vertical.

Horizontal portion 156 can be located at, below, or above the portion of hydrocarbon formation that contains hydrocarbons (e.g., oil). In some examples, at least a part of horizontal portion 156 of production well 152 can be located below horizontal portion 154 of injection well 150. In the same or different examples, the distance between adjacent production wells depends on the location of the injection wells, the distance between the injection wells, and the specific physical and chemical properties desirable for extraction and recovery of hydrocarbons from the specific hydrocarbon formation. Horizontal portion 156 can be slotted. In other examples, all of production well 152 is slotted.

Production well 152 can be coupled to pump 130. Pump 130 can pump hydrocarbons and other material out of hydrocarbon formation 101 through production well 152. Each production well can have its own pump, or some or all of the production wells can share the same pump. The same variations can apply to the water separator, the refining facility, the coker, and the storage facility.

In some examples, the injection gas is used not only to reduce the viscosity of the heavy crude oil, but it can also be used as a driving gas to displace oil in hydrocarbon formation 101. Using this technique, injection gas is injected directly into hydrocarbon formation 101 though the at least one injection well 150 in hydrocarbon formation 101, and the hydrocarbons (and injection gas) can be recovered from the at least one production well 152 in hydrocarbon formation 101.

In various embodiments, the at least one production well 152 is below the at least one injection well 150. In these embodiments, the hydrocarbons (and injector gas) can at least partially be driven from the region around the at least one injector well to the at least one production well 152 by a combination of gravity and pressure created by the introduction of the injection gas.

In other embodiments, the at least one production well 152 is located above the at least one injection well 150. In these embodiments, the pressure created by the introduction of the injection gas into hydrocarbon formation 101 can cause the hydrocarbons (and injection gas) to be driven to production well 152. Also, if the top of the hydrocarbon formation includes an impermeable or semi-impermeable cap, the injection gas (and the hydrocarbons) can accumulate below the cap and be recovered using a production well.

In the same or different embodiments, both injection well 150 and production well 152 are coupled to compressor 126 and pump 130. In these embodiments, injection gas is pumped into hydrocarbon formation 101 using both injection well 150 and production well 152. The injection gas is allowed to heat, refine, and/or pressurize hydrocarbon formation 101 for a predetermined period of time. After the predetermined period of time, hydrocarbons are pumped from hydrocarbon formation 101 using both injection well 150 and production well 152.

Instead of injection gas, prior art systems inject water or steam into hydrocarbon formation to drive the oil from the hydrocarbon formation. Steam condenses at a faster rate than injection gas which allows the injection gas to more thoroughly penetrate or permeate the hydrocarbon formation deeper than is possible with steam. Additionally, the volume of the steam decreases dramatically when it cools, and thus, the pressure in the hydrocarbon formation decreases dramatically as the steam cools. The volume of injection gas, when it cools, can decrease, but not as dramatically as steam. Thus, the pressure in the hydrocarbon formation does not decrease when the temperature of the injection gas decreases like the pressure does when steam is used. In some situations, continuing to pump injection gas into the formation will pressurize the reservoir over time and displace/drive oil to areas of the formation where the pressure is relieved (i.e., production well 152). In addition, the injection gas can partially refine the hydrocarbons in-situ, which steam does not. In some examples, the injection gas can in-situ hydrotreat the hydrocarbons.

Moreover, the molecules of the injection gas are smaller than steam (H₂O) molecules and can penetrate deeper into the hydrocarbon formation than steam. The injection gas will also rise through the formation. Thus, if the hydrocarbon formation includes an impermeable or semi-impermeable cap, the injection gas could be accumulated below the cap and can easily be collected and recycled.

Pump 130 can pump the hydrocarbons from hydrocarbon formation 101 to water separator 132. Water separator 132 removes the water from the recovered hydrocarbons. In some examples, the water removed by water separator 132 is provided to gasifier 110 to be used in the creation of the injection gas. In other examples, system 100 does not include a water separator 132.

In some examples, system 100 can include refining facility 134 to further refine the recovered hydrocarbons removed from hydrocarbon formation 101. Refining facility 134 can be a fractionator, hydrocracker, and/or a coker in some examples. Refining facility 134 can use the syngas (or a portion thereof) from gasifier 110 to refine the hydrocarbons. Benefits of performing at least some refining of the hydrocarbons on-site include allowing the hydrocarbons to be sold at a higher price. Furthermore, the by-products of the refining process can be recycled and reused by system 100, thereby decreasing the cost of operating system 100. For example, the by-products of the refining process can be used as fuel or feedstock for gasifier 110. In other embodiments, system 100 does not include refining facility 134. In these embodiments, the recovered hydrocarbons are stored in storage facility 136 or are immediately transferred to another location through a pipeline or by other techniques.

In some embodiments, gas separator 120 can receive asphaltenes (after removing sulphur with sulphur removal system 139) from refining facility 134 and can receive syngas from gasifier 110. Gas separator 120 can separate H₂ from the other gases, and output the H₂ to refining facility 134 (through compressor 140). The remaining gas can output to gasifier 110 where they can be reincorporated into the injection gas.

In other embodiments, H₂ and CO (and possibly other gases) can be provided to compressor 126 from gas separator 120. The H₂ and CO (and possibly other gases) can be used as the injection gas, instead of syngas (or syngas with sulphur containing compounds removed).

Coker 138 can receive asphaltenes and other output from refining facility 134 and can output at least pet coke, a hydrogen gas and/or C₁-C₅ hydrocarbon gas. The coke, the hydrogen gas, and/or C₁-C₅ hydrocarbon gas can be used a feedstock for gasifier 10. In some embodiments, coker 138 can thermally crack long chains of carbon in asphaltenes and other outputs from refining facility 134 into at least one of hydrogen gas, naphtha, or pet coke.

FIG. 2 illustrates an example of a method 200 of recovering hydrocarbons from a hydrocarbon formation, according to the first embodiment. Method 200 can also be considered a method of obtaining petroleum from an oil reservoir and at least partially refining the petroleum. Method 200 is merely illustrative of a technique for implementing the various aspects of certain embodiments described herein, and system 100 (FIG. 1) and method 200 are not limited to the particular embodiments described herein, as numerous other embodiments are possible.

Method 200 includes a procedure 260 of drilling one or more injection wells into the hydrocarbon formation. As an example, the one or more injection wells can be similar or identical to injection well 150 of FIG. 1.

Method 200 in FIG. 2 continues with a procedure 261 of drilling one or more production wells into the hydrocarbon formation. As an example, the one or more production wells can be similar or identical to production well 152 of FIG. 1. The sequence of procedures 260 and 261 can be revised, or procedures 260 and 261 can be performed simultaneously with each other.

Subsequently, method 200 in FIG. 2 includes a procedure 262 of producing the syngas. In various embodiments, generating the syngas includes generating the syngas having at least a predetermined temperature. In the same or different embodiment, generating the syngas can include generating the syngas to include at least one of carbon monoxide, carbon dioxide, methane, and hydrogen. The syngas can be produced in a gasifier. In various embodiments, the syngas can be ionized to more effectively refine the hydrocarbons in hydrocarbon formation 101. In many examples, the gasifier can be a portable gasifier. As an example, the gasifier can be similar or identical to gasifier 110 of FIG. 1. Procedure 262 can include heating the syngas.

Method 200 of FIG. 2 continues with a procedure 263 of processing the syngas into injection gas. In some examples, processing the syngas includes removing sulphur or sulphur-containing compounds from the syngas.

In the same or different embodiments, processing the syngas can include separating out one or more gases from the syngas. The one or more gases separated from the syngas could be the injection gas. For example, the hydrogen gas and the carbon dioxide can be separated from the other gases in the syngas. The hydrogen gas and the carbon dioxide can be provided to compressor 126 (FIG. 1) as the injection gas. In yet other embodiments, procedure 263 is skipped, and the syngas is the injection gas.

In the same or different embodiments, procedure 263 can include lowering the temperature of the syngas and/or raising the temperature of the injection gas. In some examples, heat exchanger 121 can cool the syngas and heat the injection gas. In some examples, heating the injection gas occurs after procedure 264 of compressing the injection gas.

The next procedure in method 200 is a procedure 264 of compressing the injection gas. In some examples, compressing the injection gas includes compressing the injection gas before injecting the injection gas into the hydrocarbon formation. In numerous embodiments, the injection gas can be compressed using a compressor. As an example, the compressor can be similar or identical to compressor 126 of FIG. 1.

Method 200 in FIG. 2 continues with a procedure 265 of injecting the injection gas into the hydrocarbon formation. In some examples, the injection gas can be injected into the hydrocarbon formation at a temperature such that the injection gas causes thermal cracking in at least a part of the hydrocarbons in the hydrocarbon formation. Similarly, in some examples, the injection gas is injected into the hydrocarbon formation such that the injection gas increases the pressure in the hydrocarbon formation.

In the same or different examples, the injection gas is injected into the hydrocarbon formation while the injection gas is in a supercritical state. The injection gas is injected into the hydrocarbon formation through the one or more injection wells. As an example, the one or more injection wells can be similar or identical to injection well 150 of FIG. 1.

Subsequently, method 200 in FIG. 2 includes a procedure 266 of heating the hydrocarbons in the hydrocarbon formation. In some examples, heating the hydrocarbons in the hydrocarbon formation occurs simultaneously with or immediately after the injection of the injection gas into the hydrocarbon formation. That is, the heated injection gas injected into the hydrocarbon formation causes the temperature of the hydrocarbons in the formation to increase. In many embodiments, the heating of the hydrocarbons can cause thermal cracking of at least a portion of the hydrocarbons in the hydrocarbon formation.

Method 200 in FIG. 2 continues with a procedure 267 of refining at least a part of the hydrocarbons. In some examples, the part of the hydrocarbons is refined in-situ by the injected injection gas. For example, the refining can be through solvent treatment, hydrocracking, thermal cracking, and/or hydrotreating. In the same or different embodiments, the introduction of the injection gas into the hydrocarbon formation increases the API (American Petroleum Institute) gravity and viscosity of the hydrocarbons and/or hydrocracking in at least a portion of the hydrocarbons in the hydrocarbon formation. In some examples, refining the hydrocarbons in the hydrocarbon formation occurs simultaneously or immediately after heating of the hydrocarbons and/or the injection of the injection gas into the hydrocarbon formation. Furthermore, the solvent properties of the injection gas can decrease the viscosity of the hydrocarbons.

The next procedure in method 200 is a procedure 268 of recovering at least a portion of the hydrocarbons from the hydrocarbon formation. In some examples, the hydrocarbons can be recovered from the hydrocarbon formation through the one or more production wells. As an example, the one or more production wells can be similar or identical to production well 152 of FIG. 1. The portion of the hydrocarbons can include at least some of the part of the hydrocarbons refined in procedure 267.

Method 200 in FIG. 2 continues with a procedure 269 of refining the at least a portion of the hydrocarbons. In some examples, after recovering the hydrocarbons, the at least a portion of the hydrocarbons is refined. In some examples, the refining is performed at a location located no more than a predetermined distance from the one or more production wells. In some examples, the refining is performed less than 1,000 meters from the one or more production wells. In some examples, the refining of the at least a portion of the hydrocarbons is performed at an above-ground oil refining facility. As an example, the above-ground oil refining facility can be similar or identical to refining facility 134 of FIG. 1.

In some examples, the refining of the at least a portion of the hydrocarbons produces exhaust gases or materials. These exhaust gases or materials can be used as input fuel or feedstock for the gasifier. As an example, the refining process can produce pet coke and exhaust gas. Both the pet coke and the exhaust gas can be used as input fuel and/or feedstock for the gasifier The next procedure in method 200 is a procedure 270 of storing the at least the portion of the hydrocarbons. In some examples, the portion of the hydrocarbons can be stored in storage facility 136 of FIG. 1. In other embodiments, the refined hydrocarbons are immediately transported to another site after procedure 270.

Turning to another embodiment, FIG. 3 illustrates a hydrocarbon recovery system 300 for recovering hydrocarbons from hydrocarbon formation 101, according to a second embodiment. System 300 is merely exemplary and is not limited to the embodiments presented herein. System 300 can be employed in many different embodiments or examples not specifically depicted or described herein. System 300 can be implemented using a method similar or identical to method 200 of FIG. 2.

In some embodiments, hydrocarbon recovery system 300 can include. (a) at least one gasifier 310; (b) at least one gas separator 320; (c) steam turbine 122; (d) at least one pump or compressor 126 coupled to the output of gasifier 310; (e) at least one injection well 150 coupled to compressor 126 and at least partially located in hydrocarbon formation 101; (f) at least one production well 152 at least partially located in hydrocarbon formation 101; (g) at least one pump 130 coupled to production well 152; (h) at least one water separator 132 coupled to the output of pump 130; (i) above-ground refining facility 134; (j) above-ground storage facility 136; (k) at least one coker 138; and (l) heat exchanger 321.

As an example, each part of system 300 (except, in some examples, above-ground refining facility 134 and/or above-ground storage facility 136) can be located within 1000 meters of the point on the surface of the earth directly above any part of hydrocarbon formation 101 or the point on the earth's surface where injection well 150 enters the earth. In other examples, each part of system 300 (except, in some examples, above-ground refining facility 134, and/or above-ground storage facility 136) can be located within 1000 meters of the edge of the mineral lease containing hydrocarbon formation 101. In still other examples, each part of system 300 (except, in some examples, above-ground refining facility 134, and/or above-ground storage facility 136) can be located directly over hydrocarbon formation 101 and/or tie mineral lease to reduce cost. In yet another embodiment, each part of system 300 (except, in some examples, above-ground refining facility 134 and/or above-ground storage facility 136) can be located within 10,000 meters of the point on the earth's surface where injection well 150 enters the earth.

In the embodiment illustrated in FIG. 3, gasifier 310 can use gases from gas separator 320, water from water separator 132, and feedstock 103 as input fuels and/or feedstock. Additionally, in some examples, gasifier 310 can use gas from coker 138 and refining facility 134 as fuels and/or feedstocks. Similar to gasifier 110 (FIG. 1), gasifier 310 can output syngas. Compressor 126 can pump the injection gas into injection well 150.

Furthermore, heat exchanger 321 can heat the water from water separator 132 to create steam for steam turbine 122. In some examples, heat exchanger 321 can heat the steam using heat from the syngas received from gasifier 310.

Gas separator 320 can receive syngas from gasifier 310 and output H₂ (and potentially other gases) to refining facility 134. Furthermore, gas separator 320 can output CO, CO₂, CH₄, and C₁-C₅ hydrocarbon gases to gasifier 310 as a fuel and/or saleable product.

Turing to still another embodiment, FIG. 4 illustrates a hydrocarbon recovery system 400 for recovering hydrocarbons from hydrocarbon formation 101, according to a third embodiment. System 400 is merely exemplary and is not limited to the embodiments presented herein. System 400 can be employed in many different embodiments or examples not specifically depicted or described herein. System 400 can be implemented using a method similar or identical to method 200 of FIG. 2.

In some embodiments, hydrocarbon recovery system 400 can include: (a) at least one gasifier 110; (b) at least one gas separator 120; (c) steam turbine 122; (d) at least one pump or compressor 126 coupled to the output of gas separator 120; (e) at least one injection well 150 coupled to compressor 126 and at least partially located in hydrocarbon formation 101; (f) at least one production well 152 at least partially located in hydrocarbon formation 101; (g) at least one pump 130 coupled to production well 152; (h) at least one water separator 132 coupled to the output of pump 130; (i) an above-ground refining facility 434; (j) above-ground storage facility 136; (k) at least one coker 138; (l) sulphur removal system 124; (m) a pyrolysis reactor 453; (n) a catalyst injector 454; and (o) at least two heat exchangers 421 and 459.

As an example, each part of system 400 (except, in some examples, above-ground refining facility 434 and/or above-ground storage facility 136) can be located within 1000 meters of the point on the surface of the earth directly above any part of hydrocarbon formation 101 or the point on the earth's surface where injection well 150 enters the earth. In other examples, each part of system 400 (except, in some examples, above-ground refining facility 434, and/or above-ground storage facility 136) can be located within 1000 meters of the edge of the mineral lease containing hydrocarbon formation 101. In still other examples, each part of system 400 (except, in some examples, above-ground refining facility 434, and/or above-ground storage facility 136) can be located directly over hydrocarbon formation 101 and/or the mineral lease to reduce cost. In yet another embodiment, each part of system 400 (except, in some examples, above-ground refining facility 434 and/or above-ground storage facility 136) can be located within 10,000 meters of the point on the earth's surface where injection well 150 enters the earth.

Pyrolysis reactor 453 can be coupled to an input and an output of gasifier 110. Pyrolysis reactor 453 can chemically decompose carbonaceous feedstock by heating the carbonaceous feedstock in the absence of oxygen or other reagents. In some examples, pyrolysis reactor 453 can be coupled to an output of coker 138 to receive residue and other byproducts from coker 138 to use as feedstock and/or fuel. In other embodiments, pyrolysis reactor 453 is not coupled to coker 138. In the same or different embodiment, pyrolysis reactor 453 can use feedstock 103 as feedstock. The products of the pyrolysis process in pyrolysis reactor 453 can be provided to gasifier 110 for use as feedstock and/or fuel. In addition, carbon dioxide from gasifier 110 can be provided to pyrolysis reactor 453 for use in the pyrolysis process.

Gasifier 110 can output syngas to sulphur removal system 124. Sulphur removal system 124 can remove sulphur (or sulphur containing compounds) from the syngas and provide the remaining gas to gas separator 120. Gas separator 120 can provide injection gas to compressor 126. Gas separator 120 can separate out the one or more gases out from the syngas. The one or more gases separated from the syngas can comprise the injection gas. In some examples, a portion of the syngas not used in the injection gas can be sold instead of being used by system 400. In the same or different examples, a portion of the remaining gas can be burned to create heat for steam turbine 122 (FIGS. 1, 3, 4, and 5), pyrolysis reactor 453 (FIGS. 4 and 5), gasifier 110 (FIGS. 1, 4, and 5), gasifier 310 (FIG. 3) and/or gasifier 555 (FIG. 5)

In some examples, at least some of the heat from the syngas leaving gasifier 110 can be used to heat steam for steam turbine 122 in heat exchanger 421. In the same or different embodiments, at least some of the heat from the syngas leaving gasifier 110 can be used to heat the injection gas before injection gas into hydrocarbon formation 101. In various examples, the injection gas is heated by heat exchanger 421 after the injection gas leaves compressor 126 and before catalysts are injected into catalyst injector 454. In other examples, the injection gas is heated before entering compressor 126 or after leaving catalyst injector 454. In other examples, system 400 does not include heat exchanger 421.

Catalyst injector 454 can inject one or more catalysts into the injection gas before the injection gas enters injection well 150. In one example, catalyst injector 454 adds magnesium oxide (MgO) to the injection gas. In the same or different examples, catalyst injector 454 can add aluminum oxide and/or electric arc furnace dust. The major components in electric arc furnace dust can be iron (up to 50 percent by weight) and zinc (up to 30 percent by weight), usually in an oxide form. In addition, electric arc furnace dust can include smaller quantities of calcium, magnesium, manganese, chloride, lead, cadmium and other trace elements.

In some embodiments, catalyst injector 454 is coupled to an output of compressor 126. In other examples, the catalyst can be added to the injection by catalyst injector 454 before the gas is compressed by compressor 126. Water separator 132 can remove water from the hydrocarbons pumped from production well 152 and provide the water to pyrolysis reactor 453 and/or gasifier 110. In some examples, at least one of pyrolysis reactor 453 or gasifier 110 can receive water from a different source.

In many embodiments, refined hydrocarbons leaving fractionator 457 can have an elevated temperature as a result of the refining process. Heat exchanger 459 can transfer heat from the refined hydrocarbons leaving fractionator 457 to the hydrocarbons leaving water separator 132. The hydrocarbons are heated as part of the hydrocracking process in hydrocracker 456, so transfer heat from the refined hydrocarbons before they enter hydrocracker 456 can improve the energy efficiency of system 400 and decrease the cost of the extraction and refining process. In other embodiments, system 400 does not include heat exchanger 459.

Refining facility 434 can include: (a) a hydrocracker 456; and (b) a fractionator 457. Hydrocracker 456 can receive hydrocarbons from production well 152 (via water separator 132 and pump 130) and refine the hydrocarbons. Various embodiments also include a sulphur removal system between production well 152 and hydrocracker 456.

In some embodiments, hydrocracker 456 employs a catalytic process in a hydrogen rich environment where the long chains of molecules in the hydrocarbons are broken into smaller molecules. For example, in hydrocracker 456, some of the carbon bonds within the molecules in the hydrocarbons can be broken. Hydrogen can bond to the broken carbon bonds. In various embodiments, hydrocracker 456 can operate at high temperatures (e.g., 345-425° C.) and at very high pressures of, for example, 10,000 kPa (kilopascals) to 20,000 kPa.

Fractionator 457 further refines the recovered hydrocarbons from hydrocracker 456 before the refined hydrocarbons are stored in storage facility 136. In some embodiments, fractionator 457 can heat the hydrocarbons to a predetermined temperature (e.g., 350° C.), which causes most of the hydrocarbons to evaporate. As the evaporated hydrocarbons move up through fractionator 457, each portion (or fraction) of the hydrocarbons cools and condenses at a different temperature. As each fraction condenses, the condensed hydrocarbons are collected. Portions of the hydrocarbons with a higher boiling point condense at a lower point in fractionator 457 than hydrocarbons with a lower boiling point. In some examples, system 400 does not include one or more of hydrocracker 456 and fractionator 457.

In other examples, refining facility 434 can also include an atmospheric distillation facility and/or a vacuum distillation facility. An atmospheric distillation facility is a facility that distills the crude oil at a pressure slightly above atmospheric pressure to separate lighter hydrocarbon products (e.g., gas, gasoline, naphtha, and kerosene) from the heavier crude oil. A vacuum distillation facility is a facility that distills the crude oil at a pressure lower than atmospheric pressure to separate lighter hydrocarbons from heavier crude oil.

Turning to a further embodiment, FIG. 5 illustrates a hydrocarbon recovery system 500 for recovering hydrocarbons from hydrocarbon formation 101, according to a fourth embodiment. System 500 is merely exemplary and is not limited to the embodiments presented herein. System 500 can be employed in many different embodiments or examples not specifically depicted or described herein. System 500 can be implemented using a method similar or identical to method 200 of FIG. 2.

In some embodiments, hydrocarbon recovery system 500 can include: (a) gasifiers 110 and 555; (b) at least one gas separator 120; (c) steam turbine 122; (d) at least one pump or compressor 126 coupled to the output of gas separator 120; (e) at least one injection well 150 at least partially located in hydrocarbon formation 101; (f) at least one production well 152 at least partially located in hydrocarbon formation 101; (g) at least one pump 130 coupled to production well 152; (h) at least one water separator 132 coupled to the output of pump 130; (i) an above-ground refining facility 534; (j) above-ground storage facility 136; (k) sulphur removal system 124; (l) a pyrolysis reactor 453; (m) a catalyst injector 454; and (n) heat exchangers 421 and 459.

As an example, each part of system 500 (except, in some examples, above-ground refining facility 534 and/or above-ground storage facility 136) can be located within 1000 meters of the point on the surface of the earth directly above any part of hydrocarbon formation 101 or the point on the earth's surface where injection well 150 enters the earth. In other examples, each part of system 500 (except, in some examples, above-ground refining facility 534, and/or above-ground storage facility 136) can be located within 1000 meters of the edge of the mineral lease containing hydrocarbon formation 101. In still other examples, each part of system 500 (except, in some examples, above-ground refining facility 534, and/or above-ground storage facility 136) can be located directly over hydrocarbon formation 101 and/or the mineral lease to reduce cost. In yet another embodiment, each part of system 500 (except, in some examples, above-ground refining facility 534 and/or above-ground storage facility 136) can be located within 10,000 meters of the point on the earth's surface where injection well 150 enters the earth.

In some examples, water separator 132 can provide water to pyrolysis reactor 453. In the same or different embodiments, water separator 132 also can provide water to gasifier 110 and/or 555.

Refining facility 534 includes: (a) a coker and hydrocracker 559; and (b) fractionator 457. Refining facility 534 can be use to refine and upgrade hydrocarbons removed from hydrocarbon formation 101 similar to refining facilities 134 (FIG. 1) and 434 (FIG. 4).

In this embodiment, two gasifiers 110 and 555 are used to provide syngas for system 400. The syngas from gasifiers 110 and 555 can be provided to gas separator 120 after removing any sulphur from the syngas using sulphur removal system 124. Gas separator 120 can separate one or more gases from the syngas to use as an injection gas. Using multiple gasifiers increases the amount of injection gas available for injection into hydrocarbon formation 101. Using multiple gasifiers in system 400 provides redundancy and allows more syngas to be produced (and, thus, greater and faster recovery of hydrocarbons).

In some examples, carboneous material and other byproducts from coker and hydrocracker 559 can be provided to gasifier 110 as feedstock or fuel. Carboneous material and other byproducts from pyrolysis reactor 453 can be provided to gasifier 555 as feedstock or fuel. Carbon dioxide from gasifier 555 can be provided to pyrolysis reactor 453 as feedstock. In other embodiments, pyrolysis reactor 453 can be coupled to gasifiers 110 and 555. In the same or different embedment, coker and hydrocracker 559 can be coupled to gasifiers 110 and 555.

Turning to yet another embodiment, FIG. 6 illustrates a hydrocarbon recovery system 600 for recovering hydrocarbons from a hydrocarbon formation 601, according to a fifth embodiment. System 600 is merely exemplary and is not limited to the embodiments presented herein. System 600 can be employed in many different embodiments or examples not specifically depicted or described herein.

In some embodiments, hydrocarbon recovery system 600 can include: (a) at least one gasifier 110; (b) at least two compressors 126 and 627 coupled to the output of gasifier 110; (c) at least one injection well 150 coupled to compressor 126 and at least partially located in hydrocarbon formation 601; (d) one or more transportation wells 656 and 657; (f) at least one injection well 655 coupled to compressor 627 and a cavern 660; (g) at least one production well 658 coupled to cavern 660; (h) at least one pump 130 coupled to production well 658; and (i) an above-ground storage facility 136 coupled to production well 658 through pump 130. Other parts (not shown) of hydrocarbon recovery system 600 can be similar to the embodiments of FIGS. 1 and 3-5.

As an example, each part of system 600 (except, in some examples, above-ground storage facility 136) can be located within 1000 meters of the point on the surface of the earth directly above any part of hydrocarbon formation 601, salt bed 602 and/or the mineral lease containing hydrocarbon formation 601. In still other examples, each part of system 600 (except, in some examples, above-ground storage facility 136) can be located directly over hydrocarbon formation 601, salt bed 602, and/or the mineral lease to reduce cost.

Not to be taken in a limiting sense, a simple example of a method of operation of hydrocarbon recovery system 600 could involve solution mining in a salt bed 602 under hydrocarbon formation 601 to create a cavern 660. After creating cavern 660, hot syngas or a portion thereof (i.e., a first injection gas) from gasifier 110 can be pumped into injection well 150 in hydrocarbon formation 601. The hot first injection gas heats viscous hydrocarbons in hydrocarbon formation 601 to reduce the viscosity of the hydrocarbons and, thus, increase their flow. Furthermore, the hot first injection gas can upgrade or refine the hydrocarbons before pumping the hydrocarbons from hydrocarbon formation 601. The now-mobile hydrocarbons can be drained from hydrocarbon formation 601 through transportation wells 656 and 657 into cavern 660.

Syngas or a portion thereof (i.e., a second injection gas) from gasifier 110 also can be pumped into cavern 660. In some examples, the second injection gas can pressurize the cavern 660 and thereby create an underground pressurized vessel, which can upgrade/refine the hydrocarbons. Additionally, adding the second injection gas (or hot second injection gas) into cavern 660 can enable in-situ refining (e.g., hydrocracking and/or hydrotreating) and/or increasing the API gravity of the hydrocarbons. The upgraded hydrocarbons can be pumped from cavern 660 using production well 658 and stored in storage facility 136 or transported off-site. In some examples, system 600 could be a substantially or completely emission-free system because byproducts can be reused in system 600 or stored in cavern 660 (or another similar cavern).

Cavern 660 can be a man-made or natural cavern formed in the vicinity of hydrocarbon formation 601. In some examples, cavern 660 can be a salt dome formed in a salt (sodium chloride) bed 602. Salt beds can be found interspersed with material such as anhydrite, shale, dolomite, and other more permeable salts (e.g., potassium chloride) in certain parts of the United States and other countries. Frequently, salt beds can have thicknesses of 300 to 900 meters. The salt beds can often be found 150 to 600 meters below the ground surface and in the vicinity of hydrocarbon formations. The hydrocarbon formations are often located above the salt beds.

Transportation wells 656 and 657 can transport hydrocarbons from hydrocarbon formation 601 into cavern 660. In some examples, transportation wells are formed as part of injection well 150. In other embodiments, transportation wells 656 and 657 are separate from production well 658 and injection well 655. In some examples, transportation wells 656 and 657 can be used in creating cavern 660 or drilled as part of the process of creating cavern 660. In some examples, transportation wells 656 and 657 can use gravity drainage to transport hydrocarbons from hydrocarbon formation 601 into cavern 660.

Injection well 655 can couple gasifier 110 to cavern 660. In some examples, injection well 655 can be used to pump injection gas into cavern 660. Production well 658 can couple cavern 660 to storage facility 136. That is, production well 658 (with pump 130) can be used to pump hydrocarbons from cavern 660 to storage facility 136. In some examples, instead of having a separate injection well 655 and production well 658, at least one combined well can be coupled to gasifier 110 and storage facility 136. This combined well can be used to pump injection gas into cavern 660 and remove hydrocarbons from cavern 660.

In other embodiments, system 600 can also have one or more additional production wells in hydrocarbon formation 601. These production wells could remove a portion of the hydrocarbons without first putting the hydrocarbons in cavern 660. These additional production wells can be similar or identical to production well 152 of FIGS. 1 and 6.

Furthermore, in other embodiments, system 600 could be similar to system 100, 300, 400, and/or 500 (FIGS. 1, 3, 4, and 5, respectively). That is, system 600 could include steam turbine(s), sulphur removal system(s), gas separator(s), compressor(s), catalyst injector(s), pryolisis reactor(s), water separator(s), refining facilities, coker(s), etc.

FIG. 7 illustrates a method 700 for an example of recovering hydrocarbons from a hydrocarbon formation, according to the fifth embodiment. Method 700 can also be considered a method of obtaining petroleum from an oil reservoir and at least partially refining the petroleum. Method 700 is merely illustrative of a technique for implementing the various aspects of certain embodiments described herein, and system 600 (FIG. 6) and method 700 are not limited to the particular embodiments described herein, as numerous other embodiments are possible.

Method 700 in FIG. 7 includes a procedure 760 of creating a cavern. In some examples, the cavern can be created by solution mining in a salt bed. In various embodiments, water is injected through a well (or wells) drilled into an underground salt bed or salt dome. Dissolution of the salt forms a void or cavern in the salt deposit. Salt brine is withdrawn from the cavern to empty and create the cavern. In other examples, other methods can be used to create the underground caverns. In still other examples, naturally occurring underground caverns can be used.

Subsequently, method 700 in FIG. 7 includes a procedure 761 of drilling one or more injection wells into the hydrocarbon formation. The injection wells can be similar to injection wells 150 and/or 655 in FIG. 6. In some examples, procedure 761 can be similar or identical to procedure 260 of FIG. 2.

The next procedure in method 700 in FIG. 7 is a procedure 762 of drilling one or more production wells. In some embodiments, the one or more production wells can be drilled such that they are coupled to the cavern. As an example, the one or more production wells can be similar or identical to production well 658 of FIG. 6. In the same or different examples, one or more of the production wells can be similar or identical to production well 152 of FIG. 1. In these examples, one or more first production wells can be coupled to cavern 660 (FIG. 6), and one or more second production wells can be drilled in hydrocarbon formation 601 (FIG. 6). The sequence of procedures 761 and 762 can be revised or otherwise changed, or procedures can be performed simultaneously with each other.

Method 700 in FIG. 7 continues with a procedure 763 of producing syngas. In some embodiments, producing the syngas can include creating a syngas using at least one gasifier. In various examples, procedure 763 can be similar or identical to procedure 262 of FIG. 2. In some examples, the syngas can also be compressed to a predetermined pressure and/or heated to a predetermined temperature.

Subsequently, method 700 in FIG. 7 includes a procedure 764 of injecting a first injection gas into the hydrocarbon formation. In some embodiments, injecting the first injection gas can include pumping the first injection gas into at least one injection well in the hydrocarbon formation. For example, the at least one injection welt can be similar or identical to injection well 150 of FIG. 6. In the same or different embodiment, procedure 764 can be similar or identical to procedure 264 of FIG. 2.

In some examples, the syngas produced in procedure 763 is the first injection gas. In other examples, procedure 764 can include a process similar to procedure 263 of FIG. 2. In many embodiments, processing the syngas can also include removing sulphur or sulphur-containing compounds from the syngas.

In the same or different embodiments, injecting a first injection gas can include separating out one or more gases from the syngas. The one or more gases separated from the syngas could be the injection gas. For example, hydrogen gas and carbon dioxide can be separated from the other gases in the syngas. The hydrogen gas and the carbon dioxide can be provided to compressor 126 (FIG. 1) as the injection gas.

In the same or different embodiments, injecting a first injection gas can include lowering the temperature of the syngas and/or raising the temperature of the injection gas. In some examples, beat exchanger 121 (FIG. 1) can cool the syngas and heat the injection gas.

Method 700 in FIG. 7 continues with a procedure 765 of heating and/or refining at least a part of the hydrocarbons in the hydrocarbon formation. In some examples, procedure 765 can be similar or identical to procedures 265 and/or 266 of FIG. 2.

The next procedure in method 700 in FIG. 7 is a procedure 766 of draining at least a first portion of the hydrocarbons from the hydrocarbon formation into the cavern. The first portion can include at least some of the hydrocarbons heated and/or refined in procedure 765. In some examples, the first portion of the hydrocarbons can be drained using transportation wells. The transportation wells can be similar or identical to transportation wells 656 and 657 of FIG. 6, and the cavern can be similar or identical to cavern 660 of FIG. 6.

Method 700 in FIG. 7 continues with a procedure 767 of storing the at least a first portion of hydrocarbons in the cavern. In some examples, the first portion of the hydrocarbons is stored for a few minutes, hours, days, weeks, or months in the cavern. In other examples, the cavern can act as a long-term storage facility for the hydrocarbons. In some embodiments, the hydrocarbons in the cavern can be stored long-term and used as a strategic oil reservoir.

In the same or different embodiments, the hydrocarbons can be stored in the cavern for a predetermined period of time necessary to at least partially refine the hydrocarbons. The hydrocarbons can also be stored in cavern 660 long enough to allow different components of the hydrocarbon and other substances to be separate by gravity separation. For example, after a period of time, sand mixed with the hydrocarbons will settle at the bottom of the cavern. Similarly, pet coke will eventually settle out of the other hydrocarbons.

Method 700 in FIG. 7 continues with a procedure 768 of pumping a second injection gas into the cavern. In some examples, the second injection gas is pumped into the cavern such that the at least a first portion of the hydrocarbons in the cavern is at least partially refined (or further refined) by contact with the injection gas. Pumping the second injection gas (or hot second injection gas) into the cavern can enable in-situ refining and/or increasing the API gravity and viscosity of the hydrocarbons. In the same or different examples, pumping the second injection gas into the underground cavern can pressurize the underground cavern. Pressurizing the cavern will help further refine and upgrade the hydrocarbons. As an example, the second injection gas can be pumped into the cavern using an injection well. In some embodiments, the injection well can be similar to injection well 655 of FIG. 6. The sequence of procedures 767 and 768 can be reversed, or procedures 767 and 768 can be performed simultaneously with each other.

In some examples, the second injection gas can be the same as the first injection gas. In the same or different examples, the second injection gas is syngas. In various examples, syngas can be processed in a manner similar to the process described in procedure 263 of FIG. 2 to create the second injection gas.

In many embodiments, the first injection gas can be different from the second injection gas because of the different purposes and environments of their usage. Both the first injection gas and the second injection gas can be tuned for their specific purpose and environment.

Subsequently, method 700 in FIG. 7 includes a procedure 769 of pumping at least a second portion of the hydrocarbons from the cavern. For example, the second portion of the hydrocarbons can be pumped from the cavern to a storage container using a production well. In some examples, the production well and the storage container can be similar or identical to production well 658 and storage facility 136, respectively, of FIG. 6. In some examples, procedure 769 can also include pumping at least a portion of the second injection gas from the cavern for reuse.

In some examples, method 700 can also include procedures of further refining a portion of the hydrocarbon in an above-ground refining facility similar or identical to refining facility 134 of FIG. 1 and/or procedure 268 of FIG. 2.

Turning to other embodiments, FIG. 8 illustrates a method 800 for an example of recovering hydrocarbons from two or more hydrocarbon formations using one or more gasifiers, according to a sixth embodiment. Method 800 can also be considered a method of obtaining petroleum from two or more oil reservoirs and at least partially refining the petroleum. Method 800 is merely illustrative of a technique for implementing the various aspects of certain embodiments described herein, and method 800 is not limited to the particular embodiments described herein, as numerous other embodiments are possible.

Method 800 in FIG. 8 includes a procedure 860 of providing the one or more gasifiers at a first one of the two or more hydrocarbon formations. The one or more gasifier can be portable. In some examples, providing the one or-more gasifiers at a first one of the two or more hydrocarbon formations includes placing or constructing the one or more gasifier in the vicinity of the first hydrocarbon formation. In other examples, providing the one or more gasifiers at a first one of the two or more hydrocarbon formations includes moving the one or more gasifiers from a different location to a location at the first one of the two or more hydrocarbon formations.

For example, the gasifier can be placed with 500 meters or 1000 meters of the point on the surface of the Earth directly above any part of the first hydrocarbon formation or within 500 meters or 1000 meters of an edge of a mineral lease containing the hydrocarbon formation or the point on the earth's surface where the injection well enters the earth. In other embodiments, the gasifier is placed or constructed with 100 meters of the point on the surface of the earth directly above the center of the first hydrocarbon formation or within 500 meters or 1000 meters of an edge of a mineral lease containing the hydrocarbon formation. In yet another embodiment, the gasifier can be located within 10,000 meters of the point on the earth's surface where the injection well enters the earth. In many embodiments, placing the gasifier as close as possible to the point on the earth's surface where the injection well enters the earth is preferred because less heat will be lost during the transportation of gases from the gasifier to the injection well.

In the same of different examples, the one or more gasifiers can be similar or identical to gasifier 110 of FIGS. 1 and 4-6, gasifier 310 of FIG. 3 and/or gasifier 555 of FIG. 5. The first hydrocarbon formation can be similar or identical to hydrocarbon formation 101 of FIGS. 1 and 3-5 and/or hydrocarbon formation 601 of FIG. 6.

As an example, each part of system 100 (except, in some examples, above-ground refining facility 134 and/or above-ground storage facility 136) can be located within 1000 meters of the point on the surface of the earth directly above any part of hydrocarbon formation 101 or the point on the earth's surface where injection well 150 enters the earth. In other examples, each part of system 100 (except, in some examples, above-ground refining facility 134, and/or above-ground storage facility 136) can be located within 1000 meters of the edge of the mineral lease containing hydrocarbon formation 101. In still other examples, each part of system 100 (except, in some examples, above-ground refining facility 134, and/or above-ground storage facility 136) can be located directly over hydrocarbon formation 101 and/or the mineral lease to reduce cost.

Subsequently, method 800 in FIG. 8 includes a procedure 861 of generating a first syngas using the one or more gasifiers. In various examples, procedure 861 can be similar or identical to procedure 262 of FIG. 2 and/or procedure 763 of FIG. 7. In some examples, the first injection gas can also be compressed to a predetermined pressure and/or heated to a predetermined temperature.

Method 800 in FIG. 8 continues with a procedure 862 of injecting the first injection gas into the first one of the two or more hydrocarbon formations. In some embodiments, injecting the first injection gas can include pumping the first injection gas into at least one injection well in the hydrocarbon formation. For example, the at least one injection well can be similar or identical to injection well 150 of FIGS. 1 and 3-6 and/or injection well 655 of FIG. 6. In the same or different embodiment, procedure 862 can be similar or identical to procedure 264 of FIG. 2 and/or procedures 764 and/or 768 of FIG. 7.

In some examples, the syngas generated in procedure 861 is the first injection gas. In other examples, procedure 862 can include a process similar to procedure 263 of FIG. 2. In many embodiments, injecting the first injection gas can also include removing sulphur or sulphur-containing compounds from the syngas.

In the same or different embodiments, injecting the first injection gas can include separating out one or more gases from the syngas. The one or more gases separated from the syngas could be the injection gas. For example, hydrogen gas and carbon dioxide can be separated from the other gases in the syngas. The hydrogen gas and the carbon dioxide can be provided to compressor 126 (FIG. 1) as the injection gas.

In the same or different embodiments, procedure 862 can include lowering the temperature of the syngas and/or raising the temperature of the injection gas. In some examples, heat exchanger 121 (FIG. 1) can cool the syngas and heat the injection gas.

The next procedure in method 800 of FIG. 8 is a procedure 863 of recovering the hydrocarbons from the first one of the two or more hydrocarbon formations. In some examples, the hydrocarbons can be recovered from the first hydrocarbon formation through the one or more production wells. As an example, the one or more production wells can be similar or identical to production well 152 of FIGS. 1 and 3-6 and/or production well 658 of FIG. 6. In the same or different embodiment, procedure 863 can be similar or identical to procedure 266 of FIG. 2 and/or procedure 769 of FIG. 7.

Subsequently, method 800 in FIG. 8 includes a procedure 864 of relocating or otherwise moving the one or more gasifiers from the first one of the two or more hydrocarbon formations to a second one of the two or more hydrocarbon formations. In some examples, the one or more gasifiers are physically moved from a first location in a vicinity of the first hydrocarbon formation to a vicinity of the second hydrocarbon formation. The second hydrocarbon formation can be similar or identical to hydrocarbon formation 101 of FIGS. 1 and 3-5 and/or hydrocarbon formation 601 of FIG. 6.

In some examples, moving the one or more gasifiers to a second one of the two or more hydrocarbon formations includes placing the one or more gasifier in the vicinity of the second hydrocarbon formation. For example, the gasifier can be placed with 500 meters or 1000 meters of the point on the surface of the Earth directly above the center of the second hydrocarbon formation or the point on the earth's surface where the injection well enters the earth. In other embodiments, the gasifier is placed with 100 meters of the point on the surface of the Earth directly above the center of the second hydrocarbon formation or within 500 meters or 1000 meters of an edge of a mineral lease containing the hydrocarbon formation. In other embodiments, the gasifier is placed or constructed with 100 meters of the point on the surface of the earth directly above the center of the second hydrocarbon formation or within 500 meters or 1000 meters of an edge of a mineral lease containing the second hydrocarbon formation. In yet another embodiment, the gasifier can be located within 10,000 meters of the point on the earth's surface where the injection well enters the earth. In many embodiments, placing the gasifier as close as possible to the point on the earth's surface where the injection well enters the earth is preferred because less heat will be lost during the transportation of gases from the gasifier to the injection well.

In a different embodiment, procedure 864 moves the one or more gasifiers from a first location at the hydrocarbon formation to a second location at the hydrocarbon location. In the same or different embodiment, one or more gasifier can be relocated or otherwise moved from a first facility to another facility at the hydrocarbon formation.

Method 800 in FIG. 8 continues with a procedure 865 generating a second syngas using the one or more gasifiers at the second one of the two or more hydrocarbon formations. In various examples, procedure 865 can be similar or identical to procedure 262 of FIG. 2, procedure 763 of FIG. 7 and/or procedure 861 of FIG. 8. In some examples, the first syngas is identical to the second syngas. In other examples, at least one of chemical properties, physical properties, or gas mixture of the first syngas is different than chemical properties, physical properties, or gas mixture of the second syngas.

The next procedure in method 800 in FIG. 8 is a procedure 866 of injecting a second injection gas into the second one of the two or more hydrocarbon formations. Procedure 866 can be similar or identical to procedure 264 of FIG. 2, one or more of procedures 764 and 768 of FIG. 7, and/or procedure 862 of FIG. 8.

In some examples, the second injection gas can be the same as the first injection gas. In the same or different examples, the second injection gas is syngas. In various examples, syngas can be processed in a manner similar to the process described in procedure 263 of FIG. 2 to create the second injection gas.

In many embodiments, the first injection gas can be different from the second injection gas because of the different purposes and environments of their usage. Both the first injection gas and the second injection gas can be tuned for their specific purpose and environment.

Subsequently, method 800 in FIG. 8 includes a procedure 867 of recovering the hydrocarbons from the second one of the two or more hydrocarbon formations. In the same or different embodiment, procedure 867 can be similar or identical to procedure 267 of FIG. 2, procedure 769 of FIG. 7 and/or procedure 863 of FIG. 8.

In addition to procedures 860-867, method 800 can include any additional procedures from method 200 (FIG. 2) or method 700 (FIG. 7). For example, method 800 could include a procedure of compressing the injection gas similar or identical to procedure 263 (FIG. 2) and/or a procedure of draining at least a first portion of the hydrocarbons from the hydrocarbon formation into the cavern similar or identical to procedure 766 (FIG. 7).

Although the invention has been described with reference to specific embodiments, it will be understood by those skilled in die art that various changes may be made without departing from the spirit or scope of the invention. For example, by-products of the refining/recovery process can be stored in cavern 660 (FIG. 6). In still another embodiment, injection gas can be stored in cavern 660 to be later pumped into hydrocarbon formation 601. In still another example, method 200 (FIG. 2), method 700 (FIG. 7) and/or method 800 (FIG. 8) can include a procedure of removing the sulphur or sulphur containing compounds from the injection gas(es) before pumping the injection gas(es) into the injection well. Also, the features of one embodiment described herein can be added to another embodiment described herein, and additional examples of changes have been given in the foregoing description. Accordingly, the disclosure of embodiments is intended to be illustrative of the scope of the invention and is not intended to be limiting. It is intended that the scope of the invention shall be limited only to the extent required by the appended claims. To one of ordinary skill in the art, it will be readily apparent that the systems and methods discussed herein may be implemented in a variety of embodiments, and that the foregoing discussion of certain of these embodiments does not necessarily represent a complete description of all possible embodiments. Rather, the detailed description of the drawings, and the drawings themselves, disclose at least one preferred embodiment, and may disclose alternative embodiments.

All elements claimed in any particular claim are essential to the embodiment claimed in that particular claim. Consequently, replacement of one or more claimed elements constitutes reconstruction and not repair. Additionally, benefits, other advantages, and solutions to problems have been described with regard to specific embodiments. The benefits, advantages, solutions to problems, and any element or elements that may cause any benefit, advantage, or solution to occur or become more pronounced, however, are not to be construed as critical, required, or essential features or elements of any or all of the claims.

Moreover, embodiments and limitations disclosed herein are not dedicated to the public under the doctrine of dedication if the embodiments and/or limitations: (1) are not expressly claimed in the claims; and (2) are or are potentially equivalents of express elements and/or limitations in the claims under the doctrine of equivalents. 

1. A method of recovering and extracting hydrocarbons from a hydrocarbon formations the method comprising: generating injection gas; injecting the injection gas into the hydrocarbon formation with at least a predetermined pressure and a predetermined temperature; and recovering the hydrocarbons from the hydrocarbon formation.
 2. The method of claim 1, further comprising: drilling one or more injection wells into the hydrocarbon formation, wherein: injecting the injection gas comprises: injecting the injection gas into the hydrocarbon formation with at least a predetermined pressure and a predetermined temperature through the one or more injection wells.
 3. The method of claim 1, further comprising: drilling one or more production wells into the hydrocarbon formation, wherein: recovering the hydrocarbons from the hydrocarbon formation comprises: recovering the hydrocarbons from hydrocarbon formation through the one or more production wells.
 4. The method of claim 1, wherein: generating the injection gas further comprises: generating the injection gas in at least one gasifier.
 5. The method of claim 1, wherein: generating the injection gas further comprises generating the injection gas in at least one portable gasifier.
 6. The method of claim 1 further comprises: refining the hydrocarbons after recovering the hydrocarbons.
 7. The method of claim 6, wherein: refining the hydrocarbons produces exhaust gases; and generating the injection gas comprises: generating the injection gas with at least one gasifier and using the exhaust gas as an input for one or more of the at least one gasifier.
 8. The method of claim 1, further comprises: heating the hydrocarbons in the hydrocarbon formation.
 9. The method of claim 8, wherein: heating the hydrocarbons in hydrocarbon formation occurs concurrent or subsequent to injecting the injection gas into the hydrocarbon formation.
 10. The method of claim 1, further comprises: at least partially refining the hydrocarbons while the hydrocarbons remain in the hydrocarbon formation.
 11. The method of claim 10, wherein: at least partially refining the hydrocarbons occurs concurrently with or subsequent to injecting the injection gas into the hydrocarbon formation.
 12. The method of claim 1, wherein: injecting the injection gas into the hydrocarbon formation comprises: injecting the injection gas into the hydrocarbon formation at a temperature such that the injection gas causes thermal cracking in at least a portion of the hydrocarbons in the hydrocarbon formation.
 13. The method of claim 1, wherein: injecting the injection gas into the hydrocarbon formation comprises: injecting the injection gas into the hydrocarbon formation such that the injection gas increases pressure in the hydrocarbon formation.
 14. The method of claim 13, wherein: injecting the injection gas into the hydrocarbon formation further comprises: injecting the injection gas into the hydrocarbon formation at a temperature such that thermal cracking occurs in at least a portion of the hydrocarbons in the hydrocarbon formation.
 15. The method of claim 1, further comprising: compressing the injection gas to the predetermined pressure before injecting the injection gas into the hydrocarbon formation.
 16. The method of claim 1, wherein: the injection gas comprises hydrogen and carbon dioxide.
 17. The method of claim 1, wherein: the injection gas comprises syngas.
 18. The method of claim 1, wherein: generating the injection gas comprises: generating the injection gas comprising at least one of methane, carbon monoxide, carbon dioxide, or hydrogen.
 19. The method of claim 1, further comprising: adding a catalyst to the injection gas before injecting the injection gas into the hydrocarbon formation.
 20. The method of claim 1, further comprising: creating one or more inputs for generating the injection gas using a pyrolysis reaction.
 21. The method of claim 1, further comprising: pumping the hydrocarbons into an underground cavern before recovering the hydrocarbons.
 22. The method of claim 21, wherein: recovering the hydrocarbons comprises: recovering the hydrocarbons from the hydrocarbon formation via the underground cavern.
 23. The method of claim 21, further comprising: pumping the injection gas into the underground cavern such that the hydrocarbons in the underground cavern are at least partially refined by the injection gas.
 24. The method of claim 21, further comprising: creating the underground cavern.
 25. The method of claim 21, further comprising: storing the hydrocarbons in the underground cavern.
 26. The method of claim 1, further comprising: after recovering the hydrocarbons from the hydrocarbon formation, separating water from the hydrocarbons.
 27. The method of claim 26, further comprising: generating injection gas using the water separated from the hydrocarbons.
 28. The method of claim 26, further comprising: refining the hydrocarbons after the separating the water from the hydrocarbons.
 29. The method of claim 1, further comprising: separating one or more individual gases from the injection gas; and refining the hydrocarbons using in part the one or more individual gases.
 30. The method of claim 1, further comprising: selling at least a first portion of the injection gas.
 31. The method of claim 1, further comprising: providing at least a first portion of the injection gas to a burner.
 32. The method of claim 1, wherein: generating the injection gas comprises: generating syngas; and separating one or more gases from the syngas, wherein: the one or more gases are the injection gas.
 33. The method of claim 32, further comprising: using the syngas to at least partially heat the injection gas to the predetermined temperature.
 34. The method of claim 1, further comprising: heating the injection gas and compressing the injection gas such that the injection gas is in a supercritical state when injected into the hydrocarbon formation.
 35. The method of claim 1, wherein: the injection gas is in a supercritical state when at the predetermined temperature and the predetermined pressure.
 36. A hydrocarbon recovery system configured to recover hydrocarbons from a hydrocarbon formation, the system comprising: a gasifier configured to produce synthesis gas; one or more injection wells located at least partially in the hydrocarbon formation; and one or more productions wells located at least partially in the hydrocarbon formation; wherein: the one or more injection wells are coupled to an output of the gasifier and configured to receive at least a first portion of the synthesis gas from the gasifier and conduct the at least the first portion of the synthesis gas into the hydrocarbon formation; and the one or more production wells are configured to remove at least a first portion of the hydrocarbons out of the hydrocarbon formation.
 37. The system of claim 36, further comprising: an above-ground oil refining facility coupled to the one or more production wells and configured to receive the at least the first portion of the hydrocarbons from the one or more production wells.
 38. The system of claim 37, further comprising: a coker coupled to the above-ground oil refining facility.
 39. The system of claim 36, further comprising: an above-ground storage facility coupled to the one or more production wells and configured to store the at least the first portion of the hydrocarbons.
 40. The system of claim 36, further comprising: a gas separator coupled to an output of the gasifier and an input of the above-ground oil refining facility, wherein: the gas separator is configured to provide the at least the first portion of the synthesis gas to the injection wells; and the gas separator is configured to receive at least a second portion of the synthesis gas from the gasifier.
 41. The system of claim 40, wherein: the gas separator is configured to separate at least a third portion of the synthesis gas from the synthesis gas and provide the at least the third portion of the synthesis gas to the input of the above-ground oil refining facility.
 42. The system of claim 36, further comprises: a heat exchanger configured to heat the at least first portion of the synthesis gas to a predetermined temperature.
 43. The system of claim 36, further comprising: at least one catalyst injector coupled to the output of the gasifier and an input of the one or more injection wells.
 44. The system of claim 36, further comprising: at least one pyrolysis reactor coupled to an input of the gasifier.
 45. The system of claim 36, further comprising: a compressor coupled to the output of the gasifier and an input of the one or more injection wells, wherein: the compressor is configured to pressurize the injection gas to a predetermined pressure before providing the injection gas to the one or more injection wells.
 46. A method of obtaining petroleum from an oil reservoir and at least partially refining at least a first portion of the petroleum in an underground cavern located in a vicinity of the oil reservoir, the method comprising: providing a first injection gas; pumping the first injection gas into at least one injection well in the oil reservoir; draining at least a second portion of the petroleum from the oil reservoir into the underground cavern; providing a second injection gas; and pumping the second injection gas into the underground cavern such that the at least the first portion of the petroleum in the underground cavern is at least partially refined by the second injection gas.
 47. The method of claim 46, further comprising: storing the at least the second portion of the petroleum in the underground cavern.
 48. The method of claim 46, further comprising: pumping at least a third portion of the petroleum from the oil reservoir.
 49. The method of claim 46, further comprising: after pumping the second injection (,as into the underground cavern, pumping a part of the at least the first portion of the petroleum to an above-ground storage container.
 50. The method of claim 46, wherein: pumping the second injection gas into the underground cavern pressurizes the underground cavern.
 51. The method of claim 46, further comprising: creating the underground cavern.
 52. The method of claim 51, wherein: creating the underground cavern comprises: creating the underground cavern by solution mining a portion of a salt bed.
 53. The method of claim 46, wherein: pumping the first injection gas into the at least one injection well comprises: pumping the first injection gas into the at least one injection well in the oil reservoir at a predetermined temperature such that the first injection gas causes thermal cracking in at least a portion of the petroleum in the oil reservoir.
 54. The method of claim 46, further comprising: heating the petroleum in the oil reservoir.
 55. The method of claim 46, further comprising: pumping the second injection gas into the underground cavern further comprises: pumping the second injection gas into the underground cavern at a predetermined temperature such that the second injection gas causes thermal cracking in at least a portion of the petroleum in the oil reservoir.
 56. The method of claim 46, further comprising: heating the first injection gas and compressing the first injection gas such that the first injection gas is in a supercritical state when pumped into the oil reservoir.
 57. The method of claim 46, further comprising: heating the second injection gas and compressing the second injection gas such that the second injection gas is in a supercritical state when pumped into the underground cavern.
 58. A system configured to obtain petroleum from an oil reservoir, the system comprising: a gasifier configured to produce synthesis gas; one or more injection wells in the hydrocarbon formation; one or more transportation wells configured to drain at least a first portion of the petroleum from the oil reservoir into the underground cavern; and one or more production wells coupled to the underground cavern, wherein: the one or more injection wells are coupled to an output of the gasifier and configured to receive at least a first portion of the synthesis gas from the gasifier and conduct the at least the first portion of the synthesis gas into the oil reservoir; and the one or more production wells are configured to conduct at least a first portion of the petroleum out of the underground cavern.
 59. A method of recovering hydrocarbons from two or more hydrocarbon formations using one or more gasifiers, the method comprising: providing the one or more gasifiers at a first one of the two or more hydrocarbon formations; generating a first injection gas using the one or more gasifiers; injecting the first injection gas from the one or more gasifiers into the first one of the two or more hydrocarbon formations; recovering the hydrocarbons from the first one of the two or more hydrocarbon formations; moving the one or more gasifiers from the first one of the two or more hydrocarbon formations to a second one of the two or more hydrocarbon formations; generating a second injection gas using the one or more gasifiers at the second one of the two or more hydrocarbon formations; injecting the second injection gas from the one or more gasifiers into the second one of the two or more hydrocarbon formations; and recovering the hydrocarbons from the second one of the two or more hydrocarbon formations.
 60. The method of claim 59, wherein: the first injection gas is identical to the second injection gas.
 61. The method of claim 59, wherein: at least one of chemical properties, physical properties, or gas mixture of the first injection gas is different than chemical properties, physical properties, or gas mixture of the second injection gas.
 62. A method of recovering hydrocarbons from an hydrocarbon formation using one or more gasifiers, the method comprising: providing the one or more gasifiers at a first location at the hydrocarbon formation; generating a first injection gas using the one or more gasifiers at the first location at the hydrocarbon formation; injecting the first injection gas from the one or more gasifiers into the hydrocarbon formation; recovering a first portion of the hydrocarbons from the hydrocarbon formation; moving the one or more gasifiers from the first location at the hydrocarbon formation to a second location at the hydrocarbon formation; generating a second injection gas using the one or more gasifiers at the second location at the hydrocarbon formation; injecting the second injection gas from the one or more gasifiers into the hydrocarbon formation; and recovering a second portion of the hydrocarbons from hydrocarbon formation.
 63. The method of claim 62, wherein: the first injection gas is identical to the second injection gas.
 64. The method of claim 62, wherein: at least one of chemical properties, physical properties, or gas mixture of the first injection gas is different than chemical properties, physical properties, or gas mixture of the second injection gas. 